During conventional drilling procedures, it is often desirable to conduct various tests of the wellbore and drill string while the drill string is still in the wellbore. These tests are commonly referred to as drill stem tests (“DST”). To facilitate DST, a subsea test tree (“SSTT”) carried by the drill string is positioned within the BOP stack. The SSTT is provided with one or more valves that permit the wellbore to be isolated as desired, for the performance of DST. The SSTT also permits the drill string below the SSTT to be disconnected at the seabed, without interfering with the function of the BOP. In this regard, the SSTT serves as a contingency in the event of an emergency that requires disconnection of the drillstring in the wellbore from the surface, such as in the event of severe weather or malfunction of a dynamic positioning system. As such, the SSTT includes a decoupling mechanism to unlatch the portion of the drill string in the wellbore from the drill string above the wellbore. Thereafter, the surface vessel and riser can decouple from the BOP and move to safety. Finally, the SSTT typically is deployed in conjunction with a fluted hanger disposed to land at the top of the wellbore to at least partially support the lower portion of the drillstring during DST.
During DST and other subsea operations, it is sometimes necessary to “kill” or control the well. This is normally accomplished by circulating/pumping kill weight (heavier) fluids from the surface into the well. This flow can be through the drill string/tubing within the riser and into drill string/tubing in the well. Typically this is circulated through a downhole circulation valve and back up the casing annulus, taking returns through the BOP and choke lines at the seabed. Flow can also be the other direction: flowing down the annulus and up the tubing. This essentially places heavier-weight fluids within the well bore and circulating the lighter fluids into the annulus and returning to the surface.
In other well killing scenarios, the heavier fluid may pumped down to the perforations, displacing fluid into the formation. In this scenario, the fluid can be pumped through the drill string/tubing as above. More typically this is accomplished by utilizing a circulating point in the drill string/tubing to flow heavier fluids from the surface, through the choke and kill lines in the BOP, through the annulus, through the circulating point into the tubing, and into the formation. The circulating point is typically a rupture disc-operated safety circulating valve which closes off tubing flow at the device and provides an annulus-to-tubing circulation point below the closure.
A disadvantage to conventional kill and control methods is that they can be time consuming and costly. Operation in deeper water requires considerable volumes of fluid from the surface to be pumped longer distances, which requires more time to place heavier fluids where needed.
In view of the foregoing, there is a need in the art for more efficient approaches to killing and controlling subsea wells.